U.S. patent number 7,527,775 [Application Number 11/408,294] was granted by the patent office on 2009-05-05 for co.sub.2 removal from gas using ionic liquid absorbents.
This patent grant is currently assigned to Chevron U.S.A. Inc.. Invention is credited to Laura C. Boudreau, Daniel Chinn, Michael S. Driver, De Q. Vu.
United States Patent |
7,527,775 |
Chinn , et al. |
May 5, 2009 |
CO.sub.2 removal from gas using ionic liquid absorbents
Abstract
A process and method for separating CO.sub.2 from a gaseous
stream such as natural gas. An ionic liquid comprising an anion
having a carboxylate function and an effective amount of water is
used as an adsorbent to selectively complex the CO.sub.2 yielding a
gaseous stream with a greatly reduced CO.sub.2 content. The ionic
liquid can then be readily be regenerated and recycled.
Inventors: |
Chinn; Daniel (Bay Point,
CA), Vu; De Q. (Bakersfield, CA), Driver; Michael S.
(San Francisco, CA), Boudreau; Laura C. (Houston, TX) |
Assignee: |
Chevron U.S.A. Inc. (San Ramon,
CA)
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Family
ID: |
46324322 |
Appl.
No.: |
11/408,294 |
Filed: |
April 20, 2006 |
Prior Publication Data
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Document
Identifier |
Publication Date |
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US 20060251558 A1 |
Nov 9, 2006 |
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Related U.S. Patent Documents
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Application
Number |
Filing Date |
Patent Number |
Issue Date |
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10737090 |
Dec 16, 2003 |
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Current U.S.
Class: |
423/226;
423/220 |
Current CPC
Class: |
B01D
53/1475 (20130101); B01D 53/1493 (20130101); B01D
53/14 (20130101); C10L 3/104 (20130101); B01D
53/04 (20130101); Y02C 10/06 (20130101); B01D
2252/30 (20130101); Y02C 20/40 (20200801); Y02C
10/08 (20130101); B01D 2257/504 (20130101); B01D
2252/504 (20130101); B01D 2252/2041 (20130101); B01D
2258/0283 (20130101) |
Current International
Class: |
B01D
53/14 (20060101) |
Field of
Search: |
;423/220,226,232 |
References Cited
[Referenced By]
U.S. Patent Documents
Primary Examiner: Johnson; Edward M
Attorney, Agent or Firm: Tuck; David M.
Parent Case Text
CROSS REFERENCE TO RELATED APPLICATIONS
This application is a Continuation-in-Part of U.S. patent
application Ser. No. 10/737,090 filed Dec. 16, 2003 which is
incorporated by reference herein in its entirety.
Claims
What is claimed is:
1. A process for removal of CO.sub.2 from gaseous streams,
comprising: contacting a CO.sub.2 containing gaseous stream with an
absorbent comprising from 1 to 20 wt % water and an ionic liquid
comprising a cation and an anion comprising a carboxylate moiety;
said contacting occurring at absorption conditions, to absorb at
least a portion of the CO.sub.2 from the CO.sub.2 containing
gaseous stream and forming a CO.sub.2-absorbent complex; and
recovering a gaseous product having a reduced CO.sub.2 content.
2. The process of claim 1 wherein at least a portion of the
CO.sub.2-absorbent complex is subjected to desorption conditions to
form a CO.sub.2 effluent and a stream comprising recovered
absorbent.
3. The process of claim 1 wherein the cation is selected from the
group consisting of imidazoliums and pyridiniums.
4. The process of claim 3 wherein the cation is selected from the
group consisting of bmim and hmim.
5. The process of claim 1 wherein the anion is selected from the
group consisting of acetate, propionate, substituted acetate, and
substituted propionate.
6. The process of claim 5 wherein the anion is acetate.
7. The process of claim 1 wherein the CO.sub.2 containing gaseous
stream is natural gas.
8. The process of claim 1 wherein the absorbent comprises bmim
acetate.
9. The process of claim 8 wherein the absorbent comprises 5 to 20%
water.
10. The process of claim 6 wherein the absorbent comprises 8 to 18%
water.
11. A method of separating CO.sub.2 from a hydrocarbon containing
gas, comprising: a. contacting a gas comprising CO.sub.2 and
hydrocarbon with an absorbent comprising from 1 to 20 wt % water
and an ionic liquid comprising a cation and an anion having a
carboxylate function, at absorption conditions, to form a CO.sub.2
complex; b. recovering an effluent comprising hydrocarbon gas
depleted in CO.sub.2; and c. subjecting the CO.sub.2 complex to
desorption conditions to form a stream comprising CO.sub.2 and a
stream comprising recycled absorbent.
12. The method of claim 11 wherein the cation is selected from the
group consisting of imidazoliums and pyridiniums.
13. The method of claim 12 wherein the cation is selected from the
group consisting of bmim and hmim.
14. The method of claim 11 wherein the anion is selected from the
group consisting of acetate, propionate, substituted acetate, and
substituted propionate.
15. The method of claim 14 wherein the anion is acetate.
16. The method of claim 11 wherein the CO.sub.2 containing gaseous
stream is natural gas.
17. The method of claim 11 wherein the absorbent comprises bmim
acetate.
18. The method of claim 11 wherein the absorbent comprises 5 to 20
weight % water.
19. The method of claim 15 wherein the absorbent comprises 8 to 18
weight % water.
20. The method of claim 17 wherein the absorbent comprises 8 to 18
weight % water.
Description
BACKGROUND OF THE INVENTION
Carbon dioxide (CO.sub.2) is an undesired diluent that is present
in many natural gas and other gas sources. The removal of CO.sub.2
is a common separation process in natural gas processing and is
often required to improve the fuel quality (heating value) of the
natural gas. Also, CO.sub.2 in the presence of water can be a
corrosive agent to metal pipes. As a consequence, the removal of
CO.sub.2 to acceptable specifications is required prior to
transport natural gas or in pipelines. In the natural gas
processing industry, various technologies have been employed for
CO.sub.2 removal including chemical solvents, physical solvents,
and membranes. By far, chemical solvents that reversibly react with
CO.sub.2 are most commonly used for CO.sub.2 removal. Commonly used
chemical solvents comprise amine solutions. Commercial amine
solutions useable for this purpose include monoethanolamine (MEA),
N-methyldiethanolamine (MDEA), and diethanolamine (DEA). In this
process, the amine solution (amine and water) circulate in a loop
between two key steps: absorption of CO.sub.2 and regeneration of
the amine solvent. Although an effective CO.sub.2 separation
process, amine treating presents several issues and challenges: 1.
Intensive energy requirements: During the regeneration step,
heating energy is required to break the chemical bonds between the
absorbed CO.sub.2 and solvent. Energy is also required to generate
steam within the amine regenerator to strip the CO.sub.2 from the
solvent. For some particularly strongly-absorbing amines (e.g.,
MEA) and for large circulation rates, this energy requirement can
be very high and represents a significant operating expense. Due to
the high energy requirements, CO.sub.2-rich amine solutions are
only partially regenerated to a lower CO.sub.2 loading
(CO.sub.2-lean state) during the regeneration step. 2. Corrosivity
of the amine: Amines can rapidly corrode low alloy steel such as
carbon steel. Thus, only amine solutions (in water) with carefully
controlled solution strengths are used to minimize corrosion of the
absorption column, piping, and pumps. However, this diluted
concentration requires higher circulation rates to achieve the
desired CO.sub.2 removal. High circulation rates require larger
process equipment (capital expense), increased reboiler duty
(energy/operating expense) and increased pumping costs
(energy/operating expense). Inhibitors are also typically used to
control corrosion, but are often toxic. 3. CO.sub.2 loading
capacity: CO.sub.2 loading capacity is limited by the concentration
(or diluteness) of the amine solution. Also, the regenerated amine
solution, although lean in CO.sub.2, still contains some absorbed
CO.sub.2--reducing its capacity and reducing the driving force in
the absorber. Thus, the effective, steady-state CO.sub.2 removal
rate is further lowered. So, higher circulation rates than
theoretical are required for removal of CO.sub.2 to desired levels.
It is not recommended to attempt to boost loading capacity by
increasing the amine concentration. This is due to increased
corrosion potential effecting the longevity of the equipment. Even
if corrosion inhibitors are used, serious viscosity problems can
occur when using high concentrations of amines which can lead to
hydraulic failures. 4. Degradation of amine: Amines react with
CO.sub.2 (and H.sub.2S, COS, etc.) to form various different
products that are not reversible in the regeneration step. Amines
may also degrade thermally. The third, well-studied route of amine
degradation is oxidatively, but that is mainly for flue-gas
applications and not natural gas. Trace impurities like SOX, NOX
also degrade amines. As a result, there is a `reclaimer` used to
remove the degradation products from the amine circulation loop.
This `reclaimer` step generates waste products and requires
additional energy. Also, regular amine make-up is required to
replace the lost amine. Disposal of the degradation products may
also be a concern.
Because of the significant costs involved, proper amine selection
requires careful evaluation of these factors for the specific
application since the criticality of these factors varies for
different amines. In other words, one faces a trade-off and
optimization between benefits and costs. Nevertheless, in general,
the main disadvantage for amine-based CO.sub.2 removal processes
remains the high energy consumption requirements.
Instead of chemical absorption with amine solutions as was
discussed above, physical absorption with physical solvents (e.g.,
Selexol.TM., IFPexol.TM., n-formyl morpholine (NFM)) is another
option for CO.sub.2 removal. The primary advantage of physical
solvents over amine solutions is that lower energy requirements are
needed since CO.sub.2 absorption is accomplished through physical
solubility interactions--not chemical reactions. In fact, unlike
the energy-intensive regeneration stripping columns in amine-based
chemical absorption processes, CO.sub.2 recovery via physical
absorption processes use a sequence of flash stages (i.e.,
successive pressure reductions) to desorb CO.sub.2 from the
physical solvent. However, physical absorption processes also have
several disadvantages: 1. Low CO.sub.2 capacity: Physical solvents
tend to have lower CO.sub.2 capacities than amine solvents. Thus,
higher circulation rates and larger equipment is needed. On the
other hand, CO.sub.2 absorption tends to increase significantly
with increasing CO.sub.2 concentration or partial pressure. So,
physical solvents are most attractive for high-CO.sub.2 content
gas. 2. Pickup of hydrocarbons: Significant amounts of valuable
hydrocarbons are absorbed by physical solvents. For natural gas
processing applications, some of these hydrocarbons can be lost in
the CO.sub.2 waste stream. 3. High circulation rates: Physical
solvent processes may require twice the circulation rate as amine
solutions. Higher circulation rates result in higher capital and
operating expenses. Also, absorber columns using physical solvents
typically have more stages of contact and are therefore much taller
than those employing amine solutions. 4. Solvent losses: Physical
solvents can be entrained and lost to the treated gas.
Refrigeration or water-washing may be used to minimize losses but
this requires added capital expense and increased operating
cost.
Art that relates to the use of Ionic Liquids for separations
include U.S. Pat. No. 6,623,659 ('659 patent) entitled Separation
of Olefins from Paraffins Using Ionic Liquid Solutions to Munson et
al. which provides a method for separating olefins from
non-olefins. The '659 patent uses a Group 1B metal salt (preferably
a silver salt) dissolved in ionic liquids for separating olefins
from non-olefins including paraffins, cycloparaffins, oxygenates,
aromatics, and oxygenates. The '659 patent does not relate to the
separation of CO.sub.2 nor does use the class of ionic liquids used
in the method and process of the present invention.
Another publication that discloses a method of separation using
ionic liquids is US Patent Application Publication 2003/0125599 to
Boudreau et al. Boudreau et al. relates to the separation of dienes
form olefins using a Group 1B salt in an ionic liquid solution. The
di-olefins or dienes can be selectively complexed by the Group 1B
metal salt the separated from the uncomplexed olefins. Boudreau et
al. does not discuss separation of CO.sub.2 or the use of an ionic
liquid comprising a carboxylate moiety.
In light of the limitations of the physical and chemical processes
discussed above it would be desirable to have a CO.sub.2 removal
process with some of the features of the physical absorption
processes (namely low energy for regeneration, low solvent losses,
minimal corrosion problems) and also have some of the properties of
chemical absorption processes (such as high loading capacity and
low hydrocarbon co-absorption). The present invention provides a
new process with just such desired features.
SUMMARY OF THE INVENTION
The present invention provides a process for removal of CO.sub.2
from gaseous streams, comprising: contacting a CO.sub.2 containing
gaseous stream with an absorbent comprising from 1 to 20 wt % water
and an ionic liquid comprising a cation and an anion comprising a
carboxylate moiety; said contacting occurring at absorption
conditions, to absorb at least a portion of the CO.sub.2 from the
CO.sub.2 containing gaseous stream and forming a CO.sub.2-absorbent
complex; and recovering a gaseous product having a reduced CO.sub.2
content.
In another embodiment of the present invention a method is
disclosed of separating CO.sub.2 from a hydrocarbon containing gas,
comprising: a. contacting a gas comprising CO.sub.2 and hydrocarbon
with an absorbent comprising from 1 to 20 wt % water and an ionic
liquid comprising a cation and an anion having a carboxylate
function, at absorption conditions, to form a CO.sub.2 complex; b.
recovering an effluent comprising hydrocarbon gas depleted in
CO.sub.2; and c. subjecting the CO.sub.2 complex to desorption
conditions to form a stream comprising CO.sub.2 and a stream
comprising recycled absorbent.
In an embodiment of the present invention the ionic liquid
absorbent is selected from the group consisting of hmim acetate and
bmim acetate. In a preferred embodiment of the invention the ionic
liquid absorbent useful in the present invention comprises
bmim-acetate.
Among other factors the present invention provides a new process
for removing CO.sub.2 from hydrocarbon containing gas streams using
an ionic liquid absorbent. The new process and method has a unique
mix of properties that provide advantages over prior processes. The
process of the present invention has a high CO.sub.2 capacity, low
hydrocarbon solubility (low co-absorption), and requires low energy
for regeneration of the ionic liquid absorbent. The unique set of
desirable features of the present invention makes it economically
advantageous over current commercial physical and chemical
absorption systems.
The inventors have further discovered that the presence of water
facilitates binding of the CO.sub.2 using the absorbents of the
present invention. Not to be bound by theory it is believed that
the carboxylate moity (such as acetate) interacts with water to
form a weak reversible bond with CO.sub.2.
BRIEF DESCRIPTION OF THE DRAWINGS
FIG. 1 shows a simple process flow diagram for a physical
absorption process for the removal of CO.sub.2 from a feed gas that
is usable in the process of the present invention. The ionic liquid
absorbent of the present invention is used in the absorber.
FIG. 2 provides pure CO.sub.2 loading curves at 24.degree. C. for
various solvents.
FIG. 3 shows pure CO.sub.2 loading curves (24.degree. C.),
comparing "hybrid" ionic liquids with aqueous amines and
[bmim][acetate].
FIG. 4 provides pure CH.sub.4 loading curves (24.degree. C.) for
various solvents.
FIG. 5 provides pure C.sub.3H.sub.8 loading curves (24.degree. C.)
for various solvents.
FIG. 6 shows calculated average Heats of Sorption for CO.sub.2 in
several solvents. Literature values were used for the following
solvents: 30 wt. % MEA and 50 wt. % MDEA: (Rochelle, G. T. et al.
Report to DOE No. DE-AF26-99FT01029. September 2000.) NAM: (Gross
M. et al., 1999 Laurance Reid Gas Conditioning Conference Paper.)
Pure water and [bmim][PF.sub.6]: (Anthony, J. L. et al., J. Phys.
Chem. B 2002, 106, 7315-7320.)
FIG. 7 shows the effect of temperature on CO.sub.2 solubility in
[bmim][acetate]. The solvent was used as-received, and contains 14
wt. % water.
FIG. 8 demonstrates the effect of temperature on CO.sub.2
solubility in [bmim][BF.sub.4]. The solvent was used as-received,
and contains 0.2 wt. % water.
FIG. 9 shows the impact of temperature on CO.sub.2 solubility in
the hybrid solvent, 50 wt. % MDEA, 43 wt. % [bmim][acetate], and 7
wt. % water.
FIG. 10 demonstrates the effect of temperature on CO.sub.2
solubility in the hybrid solvent, 30 wt. % MEA, 60 wt. %
[bmim][acetate], and 10 wt. % water. The temperatures used are 24,
50, and 80.degree. C.
DETAILED DESCRIPTION OF THE INVENTION
The present invention provides a novel process for the separation
of CO.sub.2 from hydrocarbon containing gaseous streams.
Surprisingly we have discovered that absorbents containing an ionic
liquid having an anion comprising a carboxylate moiety have a
particularly useful set of features for separation and or removal
of CO.sub.2 from a gaseous stream. In particular the present
invention provides a process for removal of CO.sub.2 from a
hydrocarbon containing gas such as natural gas.
Ionic Liquids
Ionic liquids are a category of compounds which are made up
entirely of ions and are liquid at or below process temperatures.
Often salts which are composed entirely of ions are solids with
high melting points, for example, above 450 degrees C. These solids
are commonly known as `molten salts` when heated to above their
melting points. An example of a common `molten salt` is NaCl, with
a melting point of 800 degree C. Ionic liquids differ from `molten
salts`, in that they have low melting points, for example, from
-100 degrees C. to 200 degree C. They tend to be liquid over a very
wide temperature range, with a liquid range of up to about 500
degrees C. or higher. Ionic liquids are generally non-volatile,
with effectively no vapor pressure. Many are air and water stable,
and can be good solvents for a wide variety of inorganic, organic,
and polymeric materials.
The properties of ionic liquids can be tailored by varying the
cation and anion pairing. Ionic liquids and their commercial
applications are described, for example, in J. Chem. Tech.
Biotechnol, 68:351-356 (1997); J. Phys. Condensed Matter, 5:(supp
34B):B99-B106 (1993); Chemical and Engineering News, Mar. 30, 1998,
32-37; J. Mater. Chem., *:2627-2636 (1998); and Chem. Rev.,
99:2071-2084 (1999), the contents of which are hereby incorporated
by reference.
Many ionic liquids are formed by reacting a nitrogen-containing
heterocyclic ring, preferably a heteroaromatic ring, with an
alkylating-agent (for example, an alkyl halide) to form a
quaternary ammonium salt, and performing ion exchange or other
suitable reactions with various Lewis acids or their conjugate
bases to form ionic liquids. Examples of suitable heteroaromatic
rings include pyridine, substituted pyridines, imidazole,
substituted imidazoles, pyrrole and substituted pyrroles. These
rings can be alkylated with virtually any straight, branched or
cyclic C.sub.1-20 alkyl group, but preferably the alkyl groups are
C.sub.1-12 groups, since groups larger than this tend to produce
low melting solids rather than ionic liquids. Various quaternary
phosphonium compounds, thioethers, and cyclic and non-cyclic
quaternary ammonium salts have also been used.
Counterions which have been used include chloroaluminate,
bromoaluminate, gallium chloride, tetrafluoroborate,
tetrachloroborate, hexafluorophosphate, nitrate, trifluoromethane
sulfonate, methylsulfonate, p-toluenesulfonate,
hexafluoroantimonate, hexafluoroarsenate, tetrachloroaluminate,
tetrabromoaluminate, perchlorate, hydroxide anion, copper
dichloride anion, iron trichloride anion, antimony hexafluoride,
copper dichloride anion, zinc trichloride anion, as well as various
lanthanum, potassium, lithium, nickel, cobalt, manganese, and other
metal ions. The ionic liquids can be neutral, basic or acidic.
Preferred anions having a carboxylate moiety (or carboxylic
functionality) are acetates or acetate analogs such as propionate,
butyrate, etc. Any anion that contains a carboxylate function,
carboxylic function or carboxylate moiety may be useful in the
present invention. In the present application the term carboxylate
is used to mean a group having the chemical formula of --COO.sup.-
where the two oxygen atoms are attached to the carbon atom. The
carbon oxygen attachment may be in the form of a carbonyl.
The form of the cation in the ionic liquid absorbent is not thought
to be as critical as the anion in the present invention however
cations that have been found to be particularly useful in the
process of the present invention include
1-butyl-3-methylimidazolium (bmim) and 1-hexyl-3-methylimidazolium
(hmim). In a preferred embodiment of the present invention the
ionic liquid should have a pure CO.sub.2 loading curve at 24
degrees C. between that of MEA (85% H.sub.2O) and Selexol when
plotted in the same manner as FIG. 2. FIG. 2 plots Solvent Loading
(cm.sup.3 STP CO.sub.2/cm.sup.3 solvent) vs Equilibrium Partial
Pressure CO.sub.2 (atm) for a number of physical and chemical
solvents.
In an alternative embodiment of the present invention the cation
may comprise a carboxylate moiety. This may be in addition to the
anion's carboxylate function or may be in place of having an anion
having a carboxylate moiety.
In still another embodiment of the present invention the ionic
liquid can have a multitude of carboxylate functions. The
carboxylate functions can be part of the anion, part of the cation
or both on the cation and anion. Examples of anions having a
multitude of carboxylate functions include but are not limited to
oxalates, malonates, succinates, citraconates, citrates, etc. As
discussed above the inventors have further discovered that the
presence of water facilitates binding of the CO.sub.2 using the
absorbents of the present invention. Not to be bound by theory it
is believed that the carboxylate moity (such as acetate) interacts
with water to form a weak reversible bond with CO.sub.2. In the
present invention the water content of the absorbent should be from
0.1 to 25 wt. %, preferably 1 to 20 wt. %, more preferably 5 to 20
wt. %, still more preferably 8 to 18 wt. %, most preferably 10 to
15 wt %. The potential benefits of this material and process are:
Comparable or higher CO.sub.2 loading capacity than amines and
physical solvents Lower energy requirements for the regeneration of
the ionic liquid Lower absorption or pickup of hydrocarbons More
chemically stable than amines: No degradation byproducts and
disposal issues Non- or less-corrosive than amines: Pure ionic
liquids or high concentrations can be used to lower circulation
rates significantly, minimizing process equipment size and
maintenance/operating costs
In one embodiment of the present invention a process employing
ionic liquids for CO.sub.2 scrubbing is shown in FIG. 1. Instead of
a regenerator column such as used in amine plants, a flash
regeneration process in one or several stages is used. In a
CO.sub.2 absorption step, regenerated (or lean) ionic liquid is
contacted countercurrently with a feed gas in the absorber column.
CO.sub.2 is absorbed from the gas into the ionic liquid. The
CO.sub.2-rich ionic liquid goes through one or several
high-pressure flash stages to recover absorbed hydrocarbons that
are compressed and recycled back to the feed to the contactor.
Absorbed CO.sub.2 is removed and the ionic liquid is regenerated in
the final flash step at atmospheric pressure. Regenerated or lean
ionic liquid is pumped back to the absorber column.
The process scheme shown in FIG. 1 is similar to that commonly used
for physical absorption processes. The flash regeneration process
is advantageous because it requires significantly lower energy
requirements than the high-temperature stripping column required
for amine-based processes. Such a process is possible because
CO.sub.2 more easily removed from the ionic liquid than from amine
solutions. Ionic liquids are also more attractive than physical
solvents because of their higher CO.sub.2 loading capacities than
those of physical solvents, requiring lower circulation rates and
smaller sizing of the process equipment. Additionally, ionic
liquids exhibit very low hydrocarbon absorption and pickup in
comparison to physical solvents, minimizing the need for the
intermediate flash and compression stages and also minimizing the
loss of valuable hydrocarbons in the CO.sub.2 waste stream.
In an alternative embodiment of the present invention the ionic
liquid solvent of the present invention may be used in chemical
solvent process. In such a process, CO.sub.2 is desorbed from the
ionic liquid in a regenerator column by means of a suitable
stripping gas (e.g., live steam, nitrogen). The practitioners
skilled in the art will select the temperature, pressure, and
composition of the stripping gas to maximize the efficiency of
CO.sub.2 recovery for a given application.
An additional advantage of the process and method of the present
invention is that losses of the ionic liquid absorbent are very
low. Ionic liquid absorbents such as a preferred absorbent
bmim-acetate have very low (effectively zero) vapor pressure. Thus
the potential for the IL absorbent being lost in the gaseous
product is minimal. The bmim-acetate used in the process and method
of the present invention was obtained from SACHEM.TM.. Ionic
liquids such as [bmim][acetate] (or bmim-acetate) can be made using
preparations available in the open literature. In the case of
[bmim][acetate], it can be made by reacting bmim-chloride with an
appropriate acetate salt or acetic acid. In a like manner many
other Ionic liquids may be made having a carboxylate function by
selecting the appropriate cation-chloride and reacting it with the
desired anion salt or acid form of the anion. More details on the
synthesis of ionic liquids can be found in the previously cited
review article by Thomas Welton: Chem. Rev., 99:2071-2084
(1999).
Ionic liquids useful in the method and process of the present
invention are also quite chemically stable. Losses of the IL
through degradation to form byproducts is also minimal. In a
preferred embodiment of the process and method of the present
invention virtually all of the ionic liquid can be recycled and
reused.
EXAMPLES
Example 1
Experimental Methods
This example shows the procedures used for generating loading
curves shown in FIG. 2. All of the ionic liquids ([bmim][acetate],
[bmim][BF.sub.4]) and physical solvents (e.g., NAM, NFM) were used
as-received. The water content for each solvent, as determined by
Karl-Fischer titration, is summarized below:
TABLE-US-00001 [bmim][acetate]: 14.0 wt. % H.sub.2O
[bmim][BF.sub.4]: 0.21 wt. % H.sub.2O NAM: 0.15 wt. % H.sub.2O NFM:
0.28 wt. % H.sub.2O
The aqueous amine solvents were prepared by diluting the pure amine
with the appropriate amount of water. The amine concentrations were
chosen to match those that are commonly used in the gas processing
and refining industries (50 wt. % MDEA, 30 wt. % MEA, etc.).
Gas sorption measurements were conducted with a static, volumetric
method. A known mass (2 to 4 grams) of solvent was added to a
clean, pressure vessel of known volume (.about.25 cm.sup.3). The
sample vessels are all equipped with a relief valve, inlet sampling
plug valve, and a digital pressure gauge. After zeroing the gauge,
the vessel was quickly pressurized with the desired gas up to the
desired pressure (30 to 150 psig). After recording the initial
pressure, the sample vessel was placed on a reciprocating shaker
bath at room temperature. As the gas inside the vessel absorbs into
the solvent, the pressure gradually decreases until equilibrium was
attained. In early experiments, the pressure was recorded after 1,
2, 4, 6, 8, 12, and 24 hours. Our observation was that pressure
remains stable after 2-hours of agitation. After recording the
final pressure, the sample vessel was heated using heating tape to
a higher temperature (50 to 80.degree. C.) and placed onto the
reciprocating shaker bath. The pressure in the vessel was observed
to increase as the gas desorbs from the solvent and accumulate in
the head space. Eventually, a new equilibrium pressure was reached
at the higher temperature. The experiments were then repeated for
different initial gas pressures and final temperatures in order to
generate a series of loading curves for each solvent.
Example 2
CO.sub.2 Loading Curves in Solvents
Gas loadings (cm.sup.3 STP/cm.sup.3 liquid) were calculated using
the ideal gas law from the initial and equilibrium gas pressures,
temperature, solvent volume, and vessel volume. The presence of air
and water vapor in the gas phase must be accounted for when
applying this method, especially for the high-temperature data.
FIG. 2 shows the room-temperature, pure CO.sub.2 loading curves for
several solvents. CO.sub.2 loadings are reported on a volumetric
basis (cm.sup.3 STP CO.sub.2/cm.sup.3 solvent) to account for any
differences in densities between the solvents. Several clear trends
can be seen in the data.
The aqueous amines (1-3) all had the highest volumetric CO.sub.2
loadings over the entire pressure range, and have curves that rise
steeply initially and then plateaus at higher pressures. This is
characteristic of chemical absorption ("chemisorption"), which is
expected because it is well-known that amine groups can reversibly
bind CO.sub.2 either as a carbamate species (with MEA) or
bicarbonate species (MDEA and MEA).
The physical solvents (6-10) all have low volumetric CO.sub.2
loadings, and have linear loading curves over the entire pressure
range. This is characteristic of physical absorption, where
CO.sub.2 is physically dissolved into the liquid without any
specific, chemical forces.
The ionic liquids are interesting in that depending on their anion
group, the solvent can behave more closely as a chemical solvent
(4) or a physical solvent (5). [bmim][acetate] shows CO.sub.2
loadings that are intermediate between the aqueous amines and
physical solvents. Without being bound to any specific theory, we
suspect that the acetate group interacts with water to form a weak,
reversible bond with CO.sub.2. One possibility is that the CO.sub.2
binds as a bicarbonate group to [bmim][acetate]. This chemistry is
not possible in the case of [bmim][BF.sub.4]. In fact, the CO.sub.2
loading curve of this ionic liquid is slightly higher than pure
water.
Example 3
CO.sub.2 Loading Curves in "Hybrid" Ionic Liquids
Experiments were performed to investigate the effect of blending
pure amines with [bmim][acetate]. FIG. 3 shows the room-temperature
CO.sub.2 loading curves for the aqueous amines (1-3),
[bmim][acetate] (4), and two different amine blends of
[bmim][acetate] (5-6). The MDEA-[bmim][acetate] blend behaved
similar to that of pure [bmim][acetate]. This is consistent with
the notion that both MDEA and [bmim][acetate] bind CO.sub.2, in the
presence of water, as a bicarbonate species. However, when the
amine was changed from MDEA to MEA, we see that the blend has the
highest observed CO.sub.2 loading curve among all ionic liquids.
With MEA, CO.sub.2 is able to bind directly as a carbamate species
at a 2:1 ratio of MEA:CO.sub.2. At higher partial pressures,
CO.sub.2 can also bind as bicarbonate species under the influence
of the [acetate] functionality. Because of these different
mechanisms, the MEA-[bmim][acetate] loading curve has a peculiar
shape. The aqueous amines (1-3) however, still have higher overall
CO.sub.2 loading curves that the ionic-liquid blends.
Example 4
CH.sub.4 and C.sub.3H.sub.8 Loading Curves in Solvents
Hydrocarbon co-absorption in solvents is sometimes a concern,
especially when physical solvents are used and/or operating at high
feed pressures. FIG. 4 shows the room-temperature loading curves
for CH.sub.4, while FIG. 5 shows the room-temperature loading
curves for C.sub.3H.sub.8. There is considerably more scatter in
the data due to the relatively small amount of hydrocarbon sorption
(i.e., there is a small difference between the experimental initial
and final pressure readings). Compared to CO.sub.2, the volumetric
amount of hydrocarbon absorbed can be 10 to 20-times lower at a
given equilibrium pressure. In both figures, the published loading
curve for the commercial solvent, SELEXOL.TM. was plotted as a
reference. All of the solvents tested in this work showed similar
or lower CH.sub.4 loadings, and substantially lower C.sub.3H.sub.8
loadings than SELEXOL.TM..
Example 5
CO.sub.2 Heats of Sorption
The energy requirement for regeneration is another important
consideration in selecting a CO.sub.2-removal solvent. Normally,
the chemical solvents have the highest volumetric capacities for
CO.sub.2 along with the highest energy requirements. The opposite
is usually true for the physical solvents. One commonly-used
parameter to assess the regeneration energy requirements is the
isosteric heat of sorption:
.DELTA..times..times..times..times..function..differential..times..times.-
.differential..times..times. ##EQU00001## Where .DELTA.H.sub.CO2 is
the heat of absorption (kJ/mol) at a given CO.sub.2 liquid loading,
X.sub.CO2 (mol CO.sub.2/mol liquid). P (atm) and T(K) are absolute
pressure and temperatures, respectively and R is the gas constant,
8.314.times.10.sup.-3 kJ/mol*K. .DELTA.H.sub.CO2 will be negative
in most cases (indicating that absorption is exothermic), and will
gradually decrease as the liquid loading, X.sub.CO2 increases. For
linear loading curves, as with most physical solvents,
.DELTA.H.sub.CO2 will be constant. .DELTA.H.sub.CO2 is easily
calculated by measuring the loading curves for CO.sub.2 at two or
more different temperatures, and re-plotting the data as P.sub.CO2
vs. X.sub.CO2. For our work, an "average" .DELTA.H.sub.CO2,measured
over the range of liquid loadings were reported for each
solvent.
FIG. 6 summarizes the .DELTA.H.sub.CO2 (kJ/mol) values for all of
the solvents tested in our work along with others reported in the
literature. For some of the better known, MEA, MDEA, and NAM
systems, we relied on literature values. The physical solvents
(water, NAM, NFM) all had the lowest absolute .DELTA.H.sub.CO2,
with values under -20 kJ/mol. The aqueous amines have the highest
absolute .DELTA.H.sub.CO2, ranging from -50 to -80 kJ/mol. As
expected, the ionic liquids all fall in between the two, depending
on the anion group. When the anion is [BF.sub.4] or [PF.sub.6], the
ionic liquid behaves as a physical solvent. With [acetate] as the
anion, the ionic liquid behaves more closely like a chemical
solvent. However, we observed that [bmim][acetate] has a
.DELTA.H.sub.CO2=-40 kJ/mol, which is lower in absolute value than
the weakest amine, 15 wt. % MEA which has -50 kJ/mol. The trends
observed in the hybrid amine-ionic liquids were also consistent.
The enhanced CO.sub.2 capacity of MEA-[bmim][acetate] upon adding
the amine functionality came at the expense of a much more
exothermic .DELTA.H.sub.CO2. In contrast, adding MDEA to
[bmim][acetate] did very little, and the .DELTA.H.sub.CO2 and
CO.sub.2 loadings were similar to that of [bmim][acetate]
alone.
Example 6
CO.sub.2 Loading Curves at Higher Temperatures
FIG. 7 through FIG. 10 summarize the loading curves at 24, 50, and
80.degree. C. for pure and amine-blended ionic liquids. The data
was plotted as P.sub.CO2(atm) vs. X.sub.CO2(mol/mol), from which
.DELTA.H.sub.CO2 may readily be determined. The loading curve for
[bmim][BF.sub.4] was linear at each temperature (i.e.,
characteristic of Henry's Law), as expected for a physical solvent.
In contrast, [bmim][acetate] and the amine-[bmim][acetate] hybrids
all exhibited strong curvature in their loading curves.
* * * * *